Subsea drilling typically involves rotating a drill bit from fixed or floating installation at the water surface or via a downhole motor at the remote end of a tubular drill string. It involves pumping a fluid down the inside of the tubular drill string, through the drill bit, and circulating this fluid continuously back to surface via the drilled space between the hole/drill string, referred to as the wellbore annulus, and the riser/drill string, referred to as the riser annulus. The drill string extends down through the internal bore of the riser pipe and into the wellbore, with the riser connecting the subsea BOP on the ocean floor to the floating installation at surface, thus providing a flow conduit for the drilling fluid and cuttings returns to be returned to the surface to the rig's fluid treatment system. The drill string is comprised of sections of tubular joints connected end to end, and their respective outside diameter depends on the geometry of the hole being drilled and their effect on the fluid hydraulics in the wellbore.
Drilling a wellbore on a floating installation requires a slip joint at the water's surface which utilizes an inner and outer barrel. The inner barrel is transient, extending and retracting from the outer barrel to compensate for the heaving motion of the vessel from ocean from tides and waves. Fluid leakage from the riser system is prevented between the inner and outer barrel of the slip joint by packers or seals which are hydraulically or pneumatically charged. Typically, the slip joint seal design is the weak point of the overall assembly, and affects its ability to seal at pressures beyond 500 psi, with the risk of leaking at lower pressures. The usual operational mode for all current installations is at atmospheric conditions, with the slip joint seals never seeing any significant pressure. Generally, the slip joint is located at the top of the riser and connects to the upper flex joint. The upper flex joint compensates for slight angular deflection from the movement of the floating installation, and connects to the diverter housing of the rig located directly below the rig's rotary table. Further details for a conventional slip joint's general arrangement are described in U.S. Pat. No. 4,626,135.
Conventionally, the well bore is open to atmospheric pressure and there is no surface applied pressure or other pressure existing within the system. The drill string rotates freely without any sealing elements imposed or acting on it at the surface, and flow is diverted at atmospheric pressure back to the rig's fluid treatment and storage system. This is achieved through gravity flow from the diverter flow line outlet, through the diverter flow line, and into the fluid treatment system at surface on the rig.
An alternative method of drilling is managed pressure drilling (MPD). This utilizes additional special equipment that has been developed to keep the well closed at all times, as the wellhead pressures in these cases are non-atmospheric, in contrast to the traditional art of the conventional overbalanced drilling method, described above. Thus, these operate as closed loop systems. Complexity increases when MPD techniques are applied offshore, and specifically the deeper the water the more difficult these operations become. The riser section from the seabed floor to the drilling platform becomes an extension of the wellbore—as water depth increases the riser length increases accordingly, the effects of the additional hydrostatic pressure and ECD exerted on the wellbore below become more pronounced.
Pressurized drilling techniques such as MPD produce a closed loop pressurized flow system generated by a pressure seal around the drill string at surface or deeper in the riser configuration with a pressure containment device at all times. Flow is diverted to a flow line by this device, referred to as a rotating control device (RCD), rotating control head (RCH), pressure control while drilling (PCWD), or rotating blow out preventer (RBOP). The function of the rotating pressure containment device is to allow the drill string and its tool joints to pass through with reciprocation/stripping or rotation while maintaining pressure integrity around the tubular.
With drilling activity in progress and the device closed a back pressure is can be applied on the annulus with the use of a choke manifold. The drill string is stripped or rotated through the pressure containment device which isolates the pressurized annulus from the external atmosphere while maintaining a seal around the drill string.
With these devices, the sealing element rotates with the drill string while maintaining the pressure integrity of the seal. The rotation is handled by a bearing which may be a thrust, roller, cone or ball bearings or a combination of these which requires an internal bearing and seals prone to mechanical failure from the imposed loads of drilling. These are well known in the art and are described in detail in U.S. Pat. No. 7,699,109B2, U.S. Pat. No. 7,926,560, and U.S. Pat. No. 6,129,152.
An alternative apparatus to this RCD technology, utilizing a non-rotating sealing device referred to as the Riser Drilling Device (RDD), is described in patent applications WO2012127227 and WO2011128690. This eliminates the requirement for a bearing assembly, with a single or dual seal sleeve assembly installed within a specified housing within the riser system and secured in place with hydraulically locking dogs/pistons. Rotation of the seal sleeve assembly with the drill string is prevented through the frictional forces of an adjacent annular packer assembly within the housing which applies pressure to the external surface of the seal sleeve when it is in position in the housing. The seal sleeve's mechanical structure and composite materials result in a high wear resistant low friction sealing face on the drill string. This system does not use the conventional bearing systems described in the prior art.
During drilling, the bit penetrates its way through layers of underground formations until it reaches target prospects—rocks which contain hydrocarbons at a given temperature and pressure. These hydrocarbons are contained within the pore space of the rock i.e. the void space and can contain water, oil, and gas constituents—referred to as reservoirs. Due to overburden forces from layers of rock above, these reservoir fluids are contained and trapped within the pore space at a known or unknown pressure, referred to as pore pressure. The pressure of fluid in the well bore required to break, or fracture, the rocks in these formations is called the formation fracture pressure.
Equivalent circulating density (ECD) is the increase in bottom hole pressure (BHP) expressed as an increase in pressure that occurs only when drilling fluid is being circulated. The ECD value reflects the total friction losses over the entire length of the wellbore annulus, from the point of fluid exiting the bit at the wellbore bottom to where it exits the well at the diverter flow line outlet on the floating installation. The ECD can result in a BHP during circulating/drilling that varies from slightly to significantly higher values when compared to static conditions i.e. no circulation.
If the BHP falls below the pore pressure, this could result in unplanned inflow of reservoir fluids into the well bore. This is referred to as a formation influx or kick, commonly called a well control incident or event. Conversely, a high BHP will present a risk of exceeding formation fracture pressures, with consequences such as lost circulation and loss of wellbore hydrostatic, and ultimately could also give rise to a formation influx or kick.
If an influx is not detected or responded to quickly enough, hydrocarbons can escape above the subsea blow out preventer (SSBOP) and into the riser. The infiltration of gas into the riser system creates an extremely hazardous situation, as the gas is now above the main safety barrier i.e. the subsea BOP and will continue to expand and increase in velocity as it migrates or circulates up the riser. This leads to the violent displacement/unloading and/or evacuation of the liquid volume from the riser. Ultimately, this could lead to an uncontrolled blow out of gas through the rig rotary table, which could be catastrophic to people, equipment and the environment as happened recently on the drilling rig ‘Deepwater Horizon’.
As such, the goal of a conventional drilling system is to maintain the BHP above the pore pressure but below the fracture pressure while taking the ECD into account to manage the BHP. Depleted formation pressures and narrow drilling windows resulting from a tight margin between the pore pressure and fracture pressure are an ever increasing challenge in wells being drilled in offshore environments. The ability to drill these wells economically and safely relies on the techniques such as MPD, described above.
If a kick or influx is detected, offshore diverters are used in conventional underbalanced drilling to divert safely the flow of fluid and gas overboard or to the rig's conventional mud gas separator (MGS), in the event that gas manages to circulate or migrate above the subsea BOP. They are the last safety barrier present in the riser to seal off the riser annulus, and are located at the top of the riser directly below the rig rotary table. Once the diverter seals around the drill string or on the open riser with no pipe, all flow from the riser is routed through either the port or starboard diverter lines to safely divert flow away from the rig floor to the MGS, or overboard away from the rig.
The general design and operation of a common diverter used offshore is described in U.S. Pat. No. 4,971,148 and U.S. Pat. No. 4,566,494.
Referring now to FIG. 1, there is shown an exemplary embodiment of a simple cross section of a prior art diverter 10′ used on floating installations for offshore drilling. The diverter 10′ includes a diverter assembly mounted in a diverter support housing 18′. The diverter assembly includes a diverter housing 12′ in which is mounted an annular elastomeric packer 14′, and a hydraulically driven piston 16′ which is movable by the supply of pressurized fluid to a close chamber (not shown) to force the packer 14′ radially inwards around the central axis AA. The packer 14′ may thus seal against a drill string extending through the housing diverter housing 12′. The hydraulic power is supplied by the control system of the diverter (not shown), and connects to the diverter through a plurality of interfaces using high pressure hydraulic lines, well known in the art.
The diverter housing 12′ is mounted in passageway in a tubular diverter support housing 18′ so that both share a common central vertical axis AA. The diverter support housing 18′ is usually connected and supported by the rotary structural support beams 19′ directly below the rig's rotary table, and is normally a permanent installation on the rig. The diverter support housing 18′ is connected to the upper flex joint (not shown) of the riser via a crossover flange 22′ on the bottom of the diverter support housing 18′.
At least one large diameter outlet port 28′ is integrated into the diverter support housing 18′, and normally two outlet ports are present to divert flow to either starboard or port side of the rig. The outlet ports 28′ can be as large as 20 inches in outer diameter, with an inner diameter A of up to 18 inches. It should be appreciated, however, that these diameters vary between manufacturers, models, and the rig design within which the diverter 10 is installed. The or each outlet port 28′ is connected to a remotely operated valve (not shown) which govern the flow of fluid from the outlet port 28′. In this embodiment, there is an additional side outlet 30′ provided to connect a riser fill up or “fill” line 32′ on the diverter support housing 18′.
Two flow line seals 34a′, 34b′ are provided between the exterior surface of the diverter housing 12′ and the interior surface of the diverter support housing 18′, one below the or each outlet port 28′ and the other above. These seals may be O-rings or any other type of seal suitable for substantially preventing leakage of fluid from the outlet port 28′ between the diverter housing 12′ and the diverter support housing 18′.
During installation, the diverter housing 12′ inserted into the diverter support housing 18′ via a running tool (not shown) connected to its running tool profile 20′. Once the diverter housing 12 is landed on a landing shoulder profile 24′ of the diverter support housing 18′, it is locked into place using multiple locking dogs or pistons 26′ situated radially around the diverter support housing 18′. It is appreciated that the mechanism for locking the diverter housing 12′ in the diverter support housing 18′ varies between manufacturers and models and may be mechanical or hydraulic, or a different type of mechanism such as J-locks well known in the art.
After the diverter housing 12′ is locked into position, the upper and lower pressure energized flow line seals 34a′, 34b′ are activated when dynamic conditions are present. The flow line seals 34a′, 34b′ energize and seal when wellbore pressure is present below the closed packer 14, and as the pressure increases they compress against the housing walls, increasing their sealing effectiveness. These prevent fluid and/or gas leakage externally to the diverter housing 12′ when wellbore pressure exists below the closed packer 14 during flow diversion through the side outlets 28′.
The outer diameter F of the diverter housing 12′ is dictated by the internal diameter of the rig's rotary table, so that the diverter housing 10 can be lowered through the rotary table for its installation below in the diverter support housing 18′. For example, one of the smallest internal diameters for an offshore rotary table is 47 inches, so a common diverter housing 12′ outer diameter F may be 46.75 inches.
The complete diverter housing 12′ and the diverter support housing 18′ has a total length E, and the length D of the support housing 18′ is used in determining the rig's riser spaceout. Lengths B and C combined provide the distance from the base of the diverter support housing 18′ to the connective support at the rotary beams. It is appreciated that all lengths B, C, D, E, the flow outlet diameter A, and the outer diameter F of the diverter housing 12′ are governed by the rig design, and thus vary on a rig to rig basis. A common diverter system and its componentry is generally rated to a maximum of 500 psi working pressure.
Conventional diverters systems have their limitations, however. For example, a conventional diverter system cannot be operated while rotating the drill string, and generally the pressure rating of the system is low due to the lower pressure rating of the slip joint packer seals, the upper flex joint, and the valves and connections directly connected to the diverter housing. Even though the pressure rating of a conventional diverter and the upper flex joint can be up to 500 psi, in reality it is ensured that the system does not operate beyond atmospheric back pressure, by always having one line open through an interlock system. Thus the conventional system may only see higher pressures when a full uncontrolled unloading of the riser occurs, when it is possible that the pressure at the diverter may reach as high as 150 psi due to the backpressure of flow through the length of diverter line that is open. As these are usually 12 to 16 inches in diameter, it can be appreciated that the flow to create even 50 psi back pressure is tremendous.
Moreover the increasing pressure in the diverter housing as gas is circulated through the system could result in leaks through the conventional slip joint seals and upper flex joint leading to a gas release below the rig floor. Additionally, the time to close a diverter can vary from 20 to 30 seconds which may prove to be catastrophic if the kick detection time was slow or delayed and gas breakout is occurring near or at the surface.
Furthermore, if the volume and pressure of the gas present is such that there is a risk of overloading the rig's conventional MGS, flow is diverted overboard to the ocean. This does have an environmental impact, of course, and so is to be avoided, wherever possible.
MPO has developed a system and method described in previously filed patent WO2013153135 for the installation of a Riser Gas Handling (RGH) system. The RGH is an operating system for handling large influxes of gas in the riser and the resultant pressurized flow from the riser, and involves operating a rapidly closing riser closure apparatus the Quick Closing Annular (QCA) to seal off the riser at a point above a flow spool provided in the riser. Flow diverts through the flow spool to a pressure control valve provided in the riser gas handling manifold at surface which is used to control the diverted flow from the riser to a high capacity MGS at surface, where the gas is safely separated from the fluid in a controlled manner.
Thus, the riser is modified with a Quick Closing Annular (QCA), described in WO2013135725, and a flow spool with flow lines connected to a gas handling manifold. Riser closing times are improved to less than 5 seconds, and the installation of the RGH system below the rig's slip joint removes the slip joint as a pressure limiter and improves the pressure and gas handling capacity of the riser system when compared to a conventional diverter system. The RGH system allows larger volumes of riser gas to be controlled safely.
An alternative system and method is disclosed in patent application WO2011/104279. In this case, a riser closure device is installed at the top of the riser between the diverter and the slip joint. This position would allow for simplified installation, repair, maintenance, or replacement of sealing mechanism of the riser closure device without having to unlatch the lower marine riser package (LMRP) from the subsea BOP. Such is the case when they are installed below the rig's tensioner ring and/or below the water line, which results in added complexities and operational time to replacement or repair. However, installation of the riser closure device above the slip joint requires pressure compensation and corresponding return fluid flow correction during the heave cycles of the rig, because the slip joint becomes confined within the closed loop system. This includes a flow control device, a pressure damper system with a pressure regulator, and a slip joint displacement meter. Using this equipment, the change in the flow rate and the resultant pressure fluctuations from the extension and retraction of the slip joint during the heave cycle are compensated and corrected for.
This allows a constant pressure to be maintained within the riser and at the bottom of the well during drilling while under the influence of rig heave, while simultaneously correcting the outflow from the riser so that influx or loss events in the wellbore are not masked. This described configuration, its associated compensation system, and its methodology are known in the prior art.
As the slip joint becomes integrated into the closed loop system, a conventional slip joint is not effective in sealing against the increased riser pressure expected from MPD or riser gas handling operations. Thus a high pressure slip joint design is required to replace the conventional slip joint, such as the apparatus described in WO 2012/143723. This incorporates a multiple annular packer arrangement on the outer barrel housing which hydraulically seals against the transient inner barrel. The multiple seals and sealing mechanism allow the high pressure slip joint to effectively seal the riser annulus at higher pressures over the heave cycle during MPD and/or gas handling operations.
Various systems and methods have been proposed to utilize existing RCD designs such that the offshore rig can be converted between a surface annular BOP/diverter for conventional drilling operations and a rotating pressure control device for pressurized drilling operations such as MPD. This is advantageous due to the increasing demand for MPD and other pressurized drilling techniques required to drill increasingly complex wells in deep water environments. Furthermore, it would be beneficial to have the capability to rotate with the diverter seals close—such as slow rotation to prevent sticking or stuck drill string while circulating out riser gas, and/or minimizing annular pressure losses after circulating out the riser gas and before continuing with drilling operations. Such systems and methods are disclosed in US 2009/0101351 and US 2008/0210471.
In US 2008/0210471 the installation of a bell nipple or other housing assembly below the existing diverter housing is required, the bell nipple/other housing assembly to be used as a docking station for an RCD bearing assembly. With the RCD bearing assembly latched into place in the housing, pressurized drilling operations are permitted, and to revert to conventional drilling the bearing assembly is retrieved. It includes its own slip joint to operate on a floating installation and thus the existing riser slip joint is replaced, resulting in a system that requires changes to the spaceout and configuration of the prevailing riser. Additionally, the bearing assembly must be removed to pass larger outer diameter (OD) components through the housing/docking station. The rig's diverter system remains active with the conventional diverter insert in place and the docking station/RCD installed below.
Another apparatus, disclosed in patent application WO 99/51852, describes a diverter head used on a subsea wellhead to divert flow using a combination of a passive and active sealing mechanism—a stripper rubber seal and a gripper seal—which rotate with the drill string.
US 2009/0101351 progresses this concept further, and proposes a system and method that utilizes the existing diverter system with an RCD. A universal marine diverter converter (UMDC) eliminates the need to remove the diverter insert/seal assembly from the diverter housing, and it is not required to change the spaceout or configuration of the current riser. The RCD housing is clamped or latched together with the UMDC housing and has an upper and lower section. These sections are attached together via a thread or another means, which allows the UMDC to be configured to the size and type of diverter housing present. The lower housing consists of a cylindrical “stinger” which extends downwards across the diverter annular packer and allows the drill string to pass through its internal profile rotating or reciprocating. The diverter's annular packer is closed on the cylindrical body to hold the UMDC housing in place, while the RCD provides the necessary seal for rotation and reciprocation of the drill string. Ejection of the bearing assembly under pressure is prevented by the larger diameter holding member on the end of the cylindrical stinger below the sealing point of the diverter packer.
With the UMDC in position, the rig is MPD-UBD enabled allowing pressurized drilling operations to proceed, while also permitting drill string rotation during the handling of gas from the riser—thus it provides a dual purpose sealing solution. With this system, the ability to seal the riser with the diverter annular packer is lost as its main function is to assist in holding the UMDC in position via the holding member—if the sealing element starts to leak there is only the subsea BOP as a contingency, which is of no assistance if gas is at the top of the riser. Historically, it has been challenging to monitor the condition of the RCD sealing elements with respect to wear and proximity to failure, which raises concerns with the UMDC in a riser gas situation if the RCD has been in service for some time. Furthermore, as with the previous concept, the UMDC must be removed to pass larger OD drill string components.
The need exists to progress the evolution of offshore diverter technology, as it has changed very little in the last two decades with respect to pressure capacity and closure speed. There is an increasing need for a rapid closing and higher pressure rated diverter system for added safety on the rig to control and remove riser gas and drill increasingly challenging reservoirs. There is a need for such a system which can be integrated into existing offshore diverter systems, requiring minimal modifications to the existing riser system, and achievable without altering the prevailing spaceout. With the increasing requirements of pressurized drilling techniques in offshore environments, there is a need for an efficient system to safely convert existing diverter infrastructure into an MPD-capable closed loop system utilizing a more reliable sealing technology than prior arts within the diverter. The inventive system and method should, for example, have compatibility with common diverter models used offshore. For new build rigs, the configuration described here can be used to replace the existing atmospheric diverter design with this improved system and method.